1. Field of the Invention
This invention generally relates to gas-to-liquid heat exchange systems and more particularly to a system allowing multiple liquid paths to provide different temperatures of feed liquid entering the system.
2. Description of the Related Art
Natural gas represents a significant source of electrical energy in the United States and other countries. It burns with few emissions and is available throughout much of the world. Its price has also been falling dramatically in recent years as new drilling techniques such as hydraulic fracturing (or fracking) have opened up previously unavailable deposits. Power plants which convert natural gas into electrical energy are efficient and, in comparison to hydroelectric projects and coal-fired plants, are relatively easy and inexpensive to construct.
In the typical plant as shown in FIG. 1, the natural gas burns in a gas turbine (11), causing the rotor of the turbine (11) to revolve and power an electrical generator (13) to which the rotor is connected. The exhaust gases—essentially carbon dioxide, certain contaminants, and steam—leave the gas turbine at about 1200° F. The heat contained in these gases, thus, can represent a significant additional source of energy. To harness this energy, the typical combined cycle, natural gas-fired power plant also includes a heat recovery steam generator (HRSG) (100) through which the hot exhaust gases pass. The HRSG (100) acts as a gas-to-liquid heat exchanger allowing the heat in the exhaust gas to be captured and reused in a steam turbine (301).
The HRSG (100) includes an inlet duct (101) where gas turbine combustion products are entering (103) and an outlet exhaust end. (105). Exhaust gas flows from the gas turbine (11) into the upstream end (103) of the duct (101). The gas then passes through a channel of tube banks (200) with the working fluid, which includes steam, steam/water mixture, and water. The exhaust gas is heating the working fluid while cooling itself. Once clear of tube banks (200), the gas passes out the downstream end (105) into a stack which directs the exhaust gases to the atmosphere. The HRSG of FIG. 1 is a two-pressure level HRSG. As such, like most HRSGs its tube banks (200) are generally composed of three functional sections within the duct (101). The first is a superheater (201), the second is an evaporator and the third is an economizer (also called a feedwater heater). As a two-pressure system, the high pressure system uses the superheater (201), a high pressure evaporator (203) and high pressure economizer (207). The low pressure system uses the low pressure evaporator (206) and a low pressure economizer (205). These are functional distinctions as tube banks are connected to each other but the functional components are arranged basically in that order from the upstream end (103) to the downstream end (105).
The liquid in tube banks (referred to as feedwater (407) herein) enters the low pressure economizer (205) as a liquid. The low pressure economizer (205) elevates the temperature of the feedwater (407). The high temperature feedwater (407) then flows into the low pressure evaporator (206) which converts a part of the feedwater (407) into low pressure saturated steam. A part of the feedwater also goes to the high pressure economizer (207). The high pressure evaporator (203) then converts that incoming water into high pressure steam. The steam from the high pressure evaporator then flow to the superheater (201) which converts the saturated steam into superheated steam. The flow of the feedwater (407) is thus loosely counter to the flow of the gas in the duct (101).
Once the feedwater (407) has been superheated, the superheated steam flows to an external steam turbine (301) which powers another electrical generator (13). After the steam turbine (301), the working fluid (407) will pass into a condenser (303) where steam at a vacuum is condensed back into liquid for reuse through the system. A condensate pump (305) delivers the feedwater (407) back to the economizer (205).
As natural gas commonly contains traces of sulfur as a contaminant which is not easily removable prior to combustion, the combustion of the natural gas in the gas turbine (11) generally causes the sulfur to combine with oxygen to produce sulfur oxides. The combustion process of the gas turbine (11) also involves large quantities of water which is simply present in the atmosphere. So long as the exhaust gases in the duct (101) remain above the acid dew point for the gases, which is generally accepted in the industry as about at least 140° F. for sulfuric acid for the concentration of sulfur expected in most natural gas, the sulfur oxides pass out of the HRSG and into the exhaust stack.
However, unless it is preheated, the feedwater (407) entering tube banks (200) within the duct (101) will generally be at only about 90° F. to about 100° F. and, thus, it is possible that tube banks (200) toward the downstream end (553) of the low pressure economizer (205), commonly called “cold rows,” will be at a temperature below the dew point of the exhaust gases (about 140° F. for exhaust gases from natural gas as indicated above). If this should occur, sulfuric acid can condense on tubes (200) toward the downstream end from the sulfur oxides in the flue gas uniting with that water to form sulfuric acid. As sulfuric acid is highly corrosive to the material of tubes (200), such formation can cause damage to tubes (200), eventually requiring a shutdown and repair of the HRSG (100) with all associated costs.
In order to deter the formation of sulfuric acid, manufacturers of HRSGs (100) have attempted to configure the HRSGs (100) such that the feedwater (407) enters the duct (101) at a temperature above the acid dew point for the exhaust gases. Specifically, raising the temperature to about 140° F. prior to the water entering the channel (200) is desired for natural gas operations. While there are a number of ways of doing this, including the use of recirculation pumps, FIG. 1 provides a more sophisticated configuration where the feedwater (407) is fed into the cold input of a liquid-to-liquid heat exchanger (307) external to the duct (101) prior to entering tubes (200) within the duct (101). To provide the hot liquid to the heat exchanger (307), feedwater (407) which has already been heated in the duct (101) is routed out of the duct (101) to the hot input of the heat exchanger (307).
The routing of partially heated feedwater (407) is accomplished through the use of a low pressure economizer (205) that includes two sections (205a) and (205b) as shown in FIGS. 2 and 3. These sections (205a) and (205b) allow for partially heated water within the low pressure economizer (205) to be sent to the external heat exchanger (307) and then back into the low pressure economizer (205). The sections (205a) and (205b) may be located in a variety of different configurations within the duct (101), but, overall, the sections (205a) and (205b) eliminate the need for a recirculation pump to preheat the feedwater (407), which can thereby simplify operation and provide one less mechanical part with the potential to break down.
FIG. 2 provides an economizer (205) where the sections (205a) and (205b) are located in series (one after the other) relative to the gas flow (591), while FIG. 3 provides an economizer (205) where the sections (205a) and (205b) are located in parallel (next to each other) relative to the gas flow (591). Between the two sections (205a) and (205b), feedwater (407) flows through the hot input on the heat exchanger (307) that is external to gas flow (591). The feedwater (407) immediately from the condenser (303) flows through the cold input of the heat exchanger (307) before entering the economizer (205). The heat exchanger (307) thus elevates the temperature of the feedwater (407) from the condenser (303), which is from about 90° F. to about 100° F., to at least 140° F. before the water (407) enters the downstream tube rows (553) of the economizer section (205a). This means that acid condensation on the downstream tube rows (553) of that section (205a) generally does not occur.
The systems of FIGS. 1 through 3 work very well for natural gas-fired gas turbines with heat recovery steam generator systems (HRSGs). However, many natural gas-fired power plants are designed to have emergency capability to allow operation when natural gas is not available. While natural gas is always a preferred fuel, sometimes there is simply not enough of it available at the power plant. Most natural gas-fired power plants capable of emergency production are designed to burn an alternative petrochemical in an emergency. Similarly, if the cost of natural gas increases dramatically, these power plants are also more flexible as they can convert to burning alternative materials full-time. The alternative material is often #2 fuel oil, which generally contains a significantly higher sulfur content than natural gas.
When #2 fuel oil is burned in the operation of the power plant of FIGS. 1 through 3, the exhaust gases entering the duct (101) generally include a higher percentage of sulfur than when natural gas is used. This increased percentage of sulfur means that the temperature at which sulfuric acid will condense on the tubes in the exhaust path (200) is increased above the 140° F. temperature at which the feedwater (407) is fed to the tube banks (200). When a recirculation pump is used, this is generally not a problem. However, for designs such as those of FIG. 2 and FIG. 3 that utilize an external heat exchanger, the system is often not capable of providing extra heat to the feedwater (407) to raise it substantially above 140° F. because of the use of different fuel and, thus, sulfuric acid can condense on the cold end tubes of the tube bank (200) designed for the 140° F. input feedwater (407) which would no longer be of sufficient temperature to prevent condensation and a full bypass of all section of the economizer (205) would be required to prevent tube bank (200) corrosion.